System, method, and apparatus for acid fracturing with scale inhibitor protection

ABSTRACT

A method for treating a subterranean formation includes forming a treatment fluid including a carrier fluid, a solid acid-precursor, and a solid scale inhibitor. The solid acid-precursor includes a material that forms an acid at downhole conditions in the subterranean formation. The method further includes adding a solid acid-responsive material into the treatment fluid, where the solid acid-responsive material enhances formation of acid from the solid acid-precursor in acidic conditions. The method includes performing an acid fracture treatment and inhibiting scale formation within the subterranean formation. The solid scale inhibitor allows for long-term scale inhibition after the treatment.

CROSS REFERENCE

This application claims priority as a divisional patent application ofU.S. patent application Ser. No. 12/175,203, now U.S. Pat. No.7,886,822, filed Jul. 17, 2008, entitled “System, Method, and Apparatusfor Acid Fracturing with Scale Inhibitor Protection” which claimspriority to U.S. Provisional Patent Application No. 60/952,395, filedJul. 27, 2007, entitled “One-Step Acid Fracture and Scale InhibitorTreatment.” Both of these applications are hereby incorporated byreference herein in their entirety.

The present application claims the benefit of U.S. Patent ProvisionalApplication No. 60/952,395 entitled “One step acid fracture and scaleinhibitor treatment”, filed Jul. 27, 2007, which is incorporated hereinby reference.

The present application is related to U.S. Patent ProvisionalApplication No. 60/952,382 entitled “Fracture treatment fluid includinga granular scale inhibitor composition and method of use”, filed Jul.27, 2007, and to United States patent application entitled “System,method, and apparatus for combined fracturing treatment and scaleinhibition” filed Jul. 17, 2008, both of which are incorporated hereinby reference.

FIELD OF THE INVENTION

The present invention relates to inhibiting scale formation in wells,and more particularly but not exclusively relates to inhibiting scaleformation and acid fracturing in a single treatment step.

BACKGROUND

The statements in this section merely provide background informationrelated to the present disclosure and may not constitute prior art.

Acid fracturing is utilized to etch flowpaths in the fracture face thatremain open after the fracture closes, and to penetrate deeply away fromthe wellbore creating flowpaths (e.g. wormholes) that help bring fluidmore quickly to the fracture and the wellbore. However, acid fracturingof formations involves many challenges. When direct acid fluids areutilized, the acid can react quickly near the wellbore and fail topenetrate deeply into the formation to increase productivity. Further,acid fluids can corrode metal parts and other components in thewellbore, causing excessive wear and picking up undesirable metals inthe fracturing fluid that can cause precipitates to form. Therefore,treatments often include retarding the acid and/or limiting the volumeor pumping time of a treatment.

Retardation mechanisms known in the art include the use of emulsifiedacids, the use of low concentration acids, gelled acids, and/or the useof liquids that form acids on contact with water allowing acid to formin the wellbore and/or formation. The use of liquids to form acids alsohas limited benefit, as acid precursors in a liquid phase react veryquickly to become acids thereby limiting the delay effect of generatingacid in the wellbore. Further, the introduction of water and/oradditional fluid volumes (e.g. due to low acid concentrations)introduces or exacerbates scale formation problems. Scale formationproblems can also be a significant problem in formations includingcarbonates, which are common formations for acid fracturing treatments.

Scale formation in fluid-producing wells can reduce productivity of thewell or even stop production completely. Scale formation chemistry isgenerally understood, and conventional scale inhibition treatments areknown in the art. However, currently available scale inhibitiontreatments suffer from several drawbacks. One conventional scaleinhibition method consists of injecting a fluid including a scaleinhibitor chemical into a formation, and flushing the chemical away fromthe wellbore with an amount of follow-up flushing fluid, where thechemical may be designed to adsorb to formation particle surfaces. Thescale inhibitor chemical may be included in a water-based or oil-basedfluid.

One conventional scale treatment involves coating particles with resin,and coating the resin with scale inhibitor to prevent the resin coatedparticles from sticking together before treatment is completed, whilethe scale inhibitor coating provides some scale inhibition after thetreatment. Unfortunately, currently available scale inhibitiontreatments suffer from a few drawbacks. For example, currently availablescale inhibition treatments do not inhibit scale for long periods oftime and therefore require repeated application. In high flow areas of awell, for example in a fracture, the scale inhibitor is removed byproducing fluid quickly reducing the effectiveness of the treatment.Also, the available concentration of scale inhibitor declines rapidlyafter initial treatment, and therefore the scale inhibition proceduremust be repeated often or overdesigned with initial concentrations muchhigher than required to inhibit scale. Accordingly, there is a demandfor further improvements in this area of technology.

SUMMARY

One embodiment is a unique treatment fluid for acid fracturing andinhibiting scale formation in a producing well. Other embodimentsinclude unique systems and methods to form acid in the formation.Further embodiments, forms, objects, features, advantages, aspects, andbenefits shall become apparent from the following description anddrawings.

BRIEF DESCRIPTION OF THE FIGURES

FIG. 1 is a schematic diagram of a system for acid fracturing and scaleinhibition.

FIG. 2A is a schematic illustration of a solid acid-responsive materialcombined in a particle with a solid acid-precursor.

FIG. 3 is a schematic illustration of a treatment fluid.

FIG. 4 is schematic flow diagram of a procedure for acid fracturing andinhibiting scale.

DESCRIPTION OF THE ILLUSTRATIVE EMBODIMENTS

For the purposes of promoting an understanding of the principles of theinvention, reference will now be made to the embodiments illustrated inthe drawings and specific language will be used to describe the same. Itwill nevertheless be understood that no limitation of the scope of theinvention is thereby intended, and any alterations and furthermodifications in the illustrated embodiments, and any furtherapplications of the principles of the invention as illustrated thereinas would normally occur to one skilled in the art to which the inventionrelates are contemplated and protected. In addition, the compositionsused/disclosed herein can also comprise some components other than thosecited. In the summary of the invention and this detailed description,each numerical value should be read once as modified by the term “about”(unless already expressly so modified), and then read again as not somodified unless otherwise indicated in context. Also, in the summary ofthe invention and this detailed description, it should be understoodthat a concentration range listed or described as being useful,suitable, or the like, is intended that any and every concentrationwithin the range, including the end points, is to be considered ashaving been stated. For example, “a range of from 1 to 10” is to be readas indicating each and every possible number along the continuum betweenabout 1 and about 10. Thus, even if specific data points within therange, or even no data points within the range, are explicitlyidentified or refer to only a few specific, it is to be understood thatinventors appreciate and understand that any and all data points withinthe range are to be considered to have been specified, and thatinventors possessed knowledge of the entire range and all points withinthe range.

FIG. 1 is a schematic diagram of a system 100 for acid fracturing andscale inhibition. The system 100 includes a wellbore 102 intersecting asubterranean formation 104. The subterranean formation 104 may be ahydrocarbon bearing formation, or any other formation where fracturingmay be utilized and inhibiting scale formation may be desirable. Incertain embodiments, the subterranean formation 104 may related to aninjection well (such as for enhanced recovery or for storage ordisposal) or a production well for other fluids such as carbon dioxideor water. In certain embodiments, the system 100 includes an amount oftreatment fluid 106. The treatment fluid 106 includes a carrier fluid105, a solid acid-precursor, and a solid scale inhibitor.

The formation 104 may be a formation that is enhanceable by an acidfracturing treatment, for example a limestone and/or dolomite reservoir,or a reservoir having acid treatable minerals mixed in with othermaterials such as sandstone. In certain embodiments, the system includesa pump 108 to fracture the formation, and to place the treatment fluid106 into the fracture 110. The fracture 110 includes an acid fracture,which may be a hydraulically initiated fracture having a fracture faceetched with acid, and/or an acid induced fracture. The fracture 110 mayinclude wormholes and/or other flowpaths into the formation 104. Thefracture 110 may be propped open with a proppant, or the fracture mayretain highly conductive flow paths after closure due to acid etching.In certain embodiments, the fracture 110 retains particulates from thetreatment fluid 106 that may not be ordinary proppant—for exampleparticles present may include solid scale inhibitor particles, solidacid-precursor particles, solid acid-responsive material particles,and/or particles that include mixtures of one or more of the precedingsolids.

In certain embodiments, the solid acid-precursor begins to hydrolyze oncontact with water, either water in the carrier fluid 105 and/or in theformation 104. The solid acid-precursor may be designed to hydrolyze atelevated temperatures such as experienced in the formation 104. Incertain embodiments, the hydrolysis rate of the solid acid-precursor isselected by changing particle sizes, compositions of the treatment fluid106, and/or by selection of a solid acid-responsive material in contactwith the treatment fluid 106. In certain embodiments, the solidacid-precursor includes a coating that delays hydrolysis. The coatingmay include a material that degrades under conditions experienced in theformation 104 and/or that degrades in the treatment fluid 106 over atime interval relevant to the expected time to perform the fracturetreatment. As the solid acid-precursor hydrolyzes, an acid is formed inthe formation 104 and fracture 108, allowing fresh acid to be formed ina region where the acid is less likely to corrode equipment and pick upmetals, and where the acid is more likely to react with favorableregions of the formation 104.

In some embodiments, the solid acid-precursor is a cyclic ester dimer oflactic acid, a cyclic ester dimmer of glycolic acid, a homopolymer oflactic acid, a homopolymer of glycolic acid, a copolymer of lactic acid,and/or a copolymer of glycolic acid. In certain embodiments, the solidacid-precursor is a copolymer of glycolic acid and/or lactic acid, andfurther includes a hydroxyl-containing moiety, a carboxylicacid-containing moiety, and/or a hydroxycarboxylic acid-containingmoiety.

In some embodiments, the fracturing fluid does not normally contain anacid when it is prepared at the surface and injected into the wellbore.However, the carrier fluid 105 may include an acid, areduced-concentration acid, intermittent stages of acid, emulsifiedacid, or any other base fluid understood in the art.

In certain embodiments, acid can be generated downhole from precursorsincluding solid cyclic dimers, or solid polymers, of certain organicacids, that hydrolyze under known and controllable conditions oftemperature, time, and pH to form the organic acids. These solidmaterials, or “acid-precursors”, result in the formation of aciddownhole, or “delayed acid generation”. One example of a suitable solidacid-precursor is the solid cyclic dimer of lactic acid (known as“lactide”), which has a melting point of 95 to 125° C., (depending uponthe optical activity). Another suitable example is a polymer of lacticacid, (sometimes called a polylactic acid (or “PLA”), or a polylactate,or a polylactide). Another suitable example is the solid cyclic dimer ofglycolic acid (known as “glycolide”), which has a melting point of about86° C. Yet another suitable example is a polymer of glycolic acid(hydroxyacetic acid), also known as polyglycolic acid (“PGA”), orpolyglycolide. Another example is a copolymer of lactic acid andglycolic acid. These polymers and copolymers are polyesters.

The PLA polymers are solids at room temperature and are hydrolyzed bywater to form lactic acid. Some typical commercially available polymershave crystalline melt temperatures of from about 120 to about 170° C.,but others are obtainable. Poly(d,l-lactide) is available with molecularweights of up to 500,000. Polyglycolic acid (also known aspolyglycolide) and various copolymers of lactic acid and glycolic acid,often called “polyglactin” or poly(lactide-co-glycolide) are alsoavailable. The rates of the hydrolysis reactions of all these materialsare governed by the molecular weight, the crystallinity (the ratio ofcrystalline to amorphous material), the physical form (size and shape ofthe solid), and in the case of polylactide, the amounts of the twooptical isomers. (The naturally occurring l-lactide forms partiallycrystalline polymers; synthetic dl-lactide forms amorphous polymers.)Amorphous regions are more susceptible to hydrolysis than crystallineregions. Lower molecular weight, less crystallinity and greatersurface-to-mass ratio all result in faster hydrolysis. Hydrolysis isaccelerated by increasing the temperature, by adding acid or base, or byadding a material that reacts with the hydrolysis product(s). Specificmaterials described herein are provided as examples only, and are notintended to be limiting.

Homopolymers can be more crystalline; copolymers tend to be amorphousunless they are block copolymers. The extent of the crystallinity can becontrolled by the manufacturing method for homopolymers and by themanufacturing method and the ratio and distribution of lactide andglycolide for the copolymers. Polyglycolide can be made in a porousform. Some of the polymers dissolve very slowly in water before theyhydrolyze. In certain embodiments, other materials may be used as solidacid-precursors such as polymers of hydroxyacetic acid (glycolic acid)with itself or other hydroxy-, carboxylic acid-, or hydroxycarboxylicacid-containing moieties, for example as described in U.S. Pat. No.4,848,467 (Formation fracturing process, assigned to E.I. DuPont deNemours and Company); U.S. Pat. No. 4,957,165 (Well treatment process,assigned to Conoco Inc.); and U.S. Pat. No. 4,986,355 (Process for thepreparation of fluid loss additive and gel breaker, assigned to ConocoInc.).

In certain embodiments, the system 100 includes a solid acid-responsivematerial in contact with the treatment fluid 106. In certainembodiments, the solid acid-responsive material contacts the treatmentfluid 106 by physical addition to the treatment fluid 106—for example asa particle added to the treatment fluid 106. In certain furtherembodiments, the solid acid-responsive material is physically mixed withthe solid acid-precursor, either prior to adding the solidacid-precursor to the carrier fluid 105 and/or by addition to thetreatment fluid 106. In certain embodiments, the solid acid-responsivematerial is a part of the formation 104, and is contacted with thetreatment fluid 106 upon injection of the treatment fluid 106 into theformation 104.

In certain embodiments, the solid acid-responsive material is a materialthat responds to an acid presence by dissolving and/or reacting. Incertain embodiments, the solid acid-responsive material is anacid-precursor hydrolysis accelerant. The solid acid-responsive materialaccelerates hydrolysis of the acid-precursor through physical and/orchemical means.

For example, the solid acid-responsive material may be included with thesolid acid-precursor in a particle, and when the solid acid-responsivematerial reacts or dissolves in the presence of acid, the particle maybreak apart into many pieces greatly increasing the surface area contactof the solid acid-precursor and accelerating the hydrolysis of theprecursor. In another example, the solid acid-responsive material may bean agent that accelerates the hydrolysis of the solid acid-precursorwhen the solid acid-responsive material dissolves into the liquid phase.In another example, the solid acid-responsive material modifies theproperties of the liquid present to enhance hydrolysis of the solidacid-precursor, for example by introducing carbon dioxide into thesolution Any acceleration mechanism understood in the art iscontemplated in the present application. In certain embodiments, morethan one acceleration mechanism from the solid acid-responsive materialmay be presented.

In certain embodiments, the solid acid-responsive material is magnesiumhydroxide, magnesium carbonate, dolomite, calcium carbonate, aluminumhydroxide, calcium oxalate, calcium phosphate, aluminum metaphosphate,sodium zinc potassium polyphosphate glass, and/or sodium calciummagnesium polyphosphate glass. In certain embodiments, the solidacid-responsive material is a water-soluble acid-precursor hydrolysisaccelerant. In certain further embodiments, the water-soluble accelerantis an ester, a cyclic ester, a diester, an anhydride, a lactone, anamide, an anhydride, an alkali metal alkoxide, a carbonate, abicarbonate, an alcohol, an alkali metal hydroxide, an ammoniumhydroxide, an amine, and/or an alkanol amine. In certain embodiments,the water-soluble accelerant is sodium hydroxide, potassium hydroxide,ammonium hydroxide, and/or propylene glycol diacetate.

In certain embodiments, the treatment fluid 106 includes solid (e.g.granular) scale inhibitor particles comprising at least partially, oreven completely, solid scale inhibitor. In certain embodiments, theamount of particles include proppant particles having a porosity—forexample porous ceramic proppant particles—and having scale inhibitorstored within the porosity. In certain further embodiments, the scaleinhibitor stored within the proppant porosity can be scale inhibitoradsorbed to internal surfaces of the proppant, and/or scale inhibitorpacked into the bulk porosity of the proppant. In certain embodiments,the proppant may be impregnated with the scale inhibitor. In certainfurther embodiments, the treatment fluid includes scale inhibitor asgranular scale inhibitor particles and further includes scale inhibitorwithin a porous proppant particle.

The storage of scale inhibitor within the defined volume of solidparticles rather than within the liquid phase of the treatment fluidallows for a greater concentration of scale inhibitor and a configurabledispersion or dissolution time for the scale inhibitor. Further, thestorage of scale inhibitor within the defined volume of solid particlesallows for a greater concentration and a configurable dispersion ordissolution time for the scale inhibitor relative to a surface coatingof scale inhibitor, including dispersion times that can be much greaterthan the dispersion times of a surface coated scale inhibitor. Incertain embodiments, additional scale inhibitor may be included in theliquid phase of the treatment fluid and/or on the surface of or as acoating for the particles.

In certain embodiments, the solid granular scale inhibitors particlesinclude mixtures, blends, and/or filled polymers and the like and may bemanufactured in various solid shapes, including, but not limited tofibers, beads, films, ribbons and platelets. The scale inhibitor may becoated to promote adsorption to surfaces or to slow dissolution.Non-limiting examples of coatings include polycaprolate (a copolymer ofglycolide and epsilon-caprolactone), and calcium stearate, both of whichare hydrophobic. The term “coating” as used herein may refer toencapsulation or simply to changing the surface by chemical reaction orby forming or adding a thin film of another material. In certain furtherembodiments, the coating includes a material that degrades in contactwith a hydrocarbon, a material that degrades at a downhole temperature,and/or a material that degrades in a formation brine.

The appropriate combination of carrier fluid, scale inhibitor and solidacid-precursor may be selected readily from available materials. Therate of dissolution of the granular scale inhibitor is governed byfactors such as the choice of material, the ratio of materials, theparticle size, calcining and coating of the solid material, the fluidsand temperature in the subterranean formation 104, and may readily andeasily be determined by routine measurements. The rate of hydrolysis ofsolid acid-precursor particles and dissolution/reaction of solidacid-responsive materials are determined according to similarconsiderations and can also be determined by routine measurements.

A scale inhibitor or inhibitors should be selected to be compatible withthe function of other components of the treatment fluid 106. Thegranular scale inhibitor and/or proppant including inhibitor may be partof a suspension in a treatment fluid in the wellbore, in theperforations, in a fracture 110, as a component of a filter cake on thewalls of a wellbore 102 or of a fracture 110, and/or in the pores of thesubterranean formation 104. In certain embodiments, the subterraneanformation 104 may be carbonate (including limestone and/or dolomite) orsandstone, although other formations benefitting from scale inhibitionare also contemplated.

In certain embodiments, the granular scale inhibitor is structured todegrade over time. The particle size of the granular scale inhibitor maybe almost any size transportable by the carrier fluid. Governing factorsfor size selection include at least a) the capability of equipment (e.g.a pump 108 and blender 112), b) the width of the fracture 110 generated,and c) the desired rate and time of particle degradation. The rate ofdegradation can readily be determined by routine measurements in alaboratory with a given fluid at a given temperature. In certainembodiments, the particles sizes of the granular scale inhibitor areselected to be similar to a proppant size and/or a fluid loss additivesize. In certain embodiments, the granular scale inhibitor includes thescale inhibitor and one or more other particulate materials.

In certain embodiments, additives are included as ordinarily used inoilfield treatment fluids 106. If an additive includes a component (suchas a buffer or a viscosifier) that may interact with the scaleinhibitor, then either the amount or nature of the scale inhibitor, orthe amount or nature of the interfering or interfered-with component maybe adjusted to compensate for the interaction. Routine measurements andfluid tests in a laboratory may quantify additive-inhibitorinteractions.

In certain embodiments, the treatment fluid 106 includes an activatorpresent in an amount between about 0.1% and 50% by weight of the scaleinhibitor. In certain further embodiments, the activator reacts with afraction of the scale inhibitor to form a gel precipitate in thefracture 110 and/or subterranean formation 104. The gel precipitateslowly dissolves in produced fluids from the subterranean formation 104,releasing scale inhibitor into the produced fluid. In certainembodiments, the activator includes a divalent ion, an ionic salt,and/or calcium chloride. In certain embodiments, the scale inhibitorincludes a chemical that adsorbs to the matrix of the subterraneanformation 104, with or without the addition of an activator.

In certain embodiments, the scale inhibitor includes a compound thatinhibits the formation of carbonate and/or phosphate scales. In certainembodiments, the scale inhibitor includes a compound includingsulfonates, phosphate esters, phosphonates, phosphonate polymers,polyacrylates and polymethacrylates, polycarboxylates, and phosphorouscontaining polycarboxylates, and/or phosphonic acid derivatives. Incertain embodiments, the scale inhibitor includes a compound includingphospino-polylacrylates and/or phosphonic acid ethylene diaminederivatives. In certain embodiments, the scale inhibitor includes acompound including phosphonic acid[1,2-ethanediylbis[nitrilobis(methylene)]]tetrakis, calcium salts thereof, and/or sodiumsalts thereof. In certain embodiments, the scale inhibitor includes acompound represented by at least one of the following structures:

In certain embodiments, the polymeric and phosphorous type scaleinhibitors described preceding are used in brines having pH valuesbetween 5.0-8.5. At pH values outside of this range, the effectivenessof these scale inhibitors decreases. However, they may be used at avariety of temperatures and pH ranges including at pH values outside ofthe described range.

In certain embodiments, hydrolysis of the solid acid-precursors isaccelerated by the addition of certain chemical agents. In certainembodiments, a small amount of the accelerating agent (the solidacid-responsive material, or accelerant) is necessary to disrupt thesurface and/or otherwise start the hydrolysis process. In certainembodiments, additional accelerant is provided to further accelerate thehydrolysis process. In certain embodiments, no accelerant is included.

In certain embodiments, the solid accelerant does not accelerate theinitial hydrolysis of the solid acid-precursor, as the solid accelerantdoes not interact with the solid acid-precursor. As the solidacid-precursor begins to hydrolyze, the resultant acid reacts with thesolid acid-responsive accelerant, which then accelerates the furtherhydrolysis of the solid acid-precursor. Other accelerant mechanisms areunderstood and contemplated in the present application. For example, theincreasing temperature as the treatment fluid 106 enters the formationcan trigger dissolution of the accelerant, as well as degradation ofcoatings and/or other mechanisms. In certain embodiments, the formation104 includes a solid accelerant. Furthermore, the action of accelerantsmay be delayed, for example, if they are slowly soluble solids or ifthey are chemically bound in a liquid chemical that must be hydrolyzedto release the agent. In certain embodiments, a first solidacid-precursor may be an accelerant for a second solid acid-precursor;for example, PGA accelerates the hydrolysis of PLA. In certainembodiments, a first solid acid-precursor that accelerates a secondsolid acid-precursor is the solid acid-responsive material. The timingand rate of hydrolysis of the solid acid-precursor is controlled bythese techniques.

In certain embodiments, the hydrolysis of solid acid-precursors isaccelerated by adding solid materials that are acid-responsive (e.g.acid-soluble and/or acid-reactive), such as but not limited to magnesiumhydroxide, magnesium carbonate, dolomite (magnesium calcium carbonate),calcium carbonate, aluminum hydroxide, calcium oxalate, calciumphosphate, aluminum metaphosphate, sodium zinc potassium polyphosphateglass, and sodium calcium magnesium polyphosphate glass, may be mixedwith or incorporated into, solid acid-precursors. These mixtures arecontacted with the treatment fluid 106, by addition at the surfaceand/or by contact within the wellbore 102 and/or formation 104. At leasta portion of the solid acid-precursor slowly hydrolyzes at controllablerates to release acids at pre-selected locations and times in thefracture. In addition to reacting with the formation fracture face, theacids also react with and dissolve at least a portion of theacid-responsive materials. In certain embodiments, most or all of thesolid material initially added is no longer present at the end of thetreatment. However, it is not necessary either for all of the solidacid-precursor to hydrolyze or for all of the solid acid-responsivematerial to dissolve. In certain embodiments, remaining solids act as aproppant in the fracture 110.

The hydrolysis of solid acid-precursors in acid fracturing may also beaccelerated by the addition of certain water-soluble acid-precursorhydrolysis accelerants. These accelerants may be acids, bases, orsources of acids or bases. In certain embodiments, water-solubleacid-precursor hydrolysis accelerants are included at low temperatures(for example below about 135° C.), at which the solid acid-precursorshydrolyze slowly and solid acid-responsive materials also dissolveslowly. Non-limiting examples of such soluble liquid additives thathydrolyze to release organic acids are esters (including cyclic esters),diesters, anhydrides, lactones and amides. A suitable compound andamount that hydrolyzes at the appropriate rate for the temperature ofthe formation 104 and the pH of the treatment fluid 106 is readilyidentified for a given treatment by simple laboratory hydrolysisexperiments.

In certain embodiments, the water-soluble acid-precursor hydrolysisaccelerants are bases. For example, the water-soluble acid-precursorhydrolysis accelerants may include sodium hydroxide, potassiumhydroxide, and/or ammonium hydroxide. In certain embodiments, thewater-soluble acid-precursor hydrolysis accelerants may includealkoxides, water-soluble carbonates and bicarbonates, methanol, ethanol,other alcohols, alkanol amines and organic amines such monoethanol amineand methyl amine. In certain embodiments, the water-solubleacid-precursor hydrolysis accelerants may include acids, for examplehydrochloric acid, hydrofluoric acid, ammonium bifluoride, formic acid,acetic acid, lactic acid, glycolic acid, aminopolycarboxylic acids (suchas but not limited to hydroxyethyliminodiacetic acid),polyaminopolycarboxylic acids (such as but not limited tohydroxyethylethylenediaminetriacetic acid), salts—including partialsalts—of the organic acids (for example, ammonium, potassium or sodiumsalts), and mixtures of these acids or salts. For the purposes herein,ammonium bifluoride partially hydrolyzes in contact with water to formsome HF, and so is considered an acid herein. The organic acids may beincluded as salts. In certain embodiments, the treatment fluid 106includes corrosion inhibitors.

In certain embodiments, the mixtures of one or more solidacid-precursors and one or more solid scale inhibitors, and optionallyone or more solid acid-responsive materials, include purely physicalmixtures of separate particle types, each particle type including one ofthe separate components. In certain embodiments, the mixtures includeparticles manufactured such that one or more solid acid-precursors,solid scale inhibitors and one or more solid acid-responsive materialsis in each particle. One example of such manufacturing includes, withoutlimitation, coating the acid-responsive material with the solidacid-precursor, or by heating a physical mixture until the solidacid-precursor melts, mixing thoroughly, cooling, and comminuting theresultant particles. In another manufacturing example, polymers areco-extruded with mineral filler materials, such as talc or carbonates,so that they have altered optical, thermal and/or mechanical properties.Such mixtures of polymers and solids are commonly referred to as “filledpolymers”.

In one embodiment, the distribution of the components in the mixtures isas uniform as possible. The choices and relative amounts of thecomponents are adjusted for the situation to control the solidacid-precursor hydrolysis rate. The most important factors will be thetemperature at which the treatment will be carried out, the compositionof the aqueous fluid or fluids with which the mixture will come intocontact, and the time and rate desired for generation of the acid.

Each of the individual ingredients, i.e., the solid acid-precursors,scale inhibitors and the optional solid acid-reactive materials, ormixtures/blends/filled polymers of solid acid-precursors, scaleinhibitors and optional solid acid-reactive materials may bemanufactured in various solid shapes, including, but not limited tofibers, beads, films, ribbons and platelets. Each individual solidmaterial or the mixtures of the solid acid-precursor and the scaleinhibitor or the mixtures of solid acid-precursor, scale inhibitor andoptional solid acid-reactive material may be coated to slow thehydrolysis. Suitable coatings include polycaprolate (a copolymer ofglycolide and epsilon-caprolactone), and calcium stearate, both of whichare hydrophobic. Polycaprolate itself slowly hydrolyzes.

Generating a hydrophobic layer on the surface of the solidacid-precursors or the mixtures of solid acid-precursors and solidacid-reactive materials by any means delays the hydrolysis. The term“coating” as used herein may refer to encapsulation or simply tochanging the surface by chemical reaction or by forming or adding a thinfilm of another material. Another suitable method of delaying thehydrolysis of the solid acid-precursor, and the release of acid, is tosuspend the solid acid-precursor, optionally with a hydrophobic coating,in oil or in the oil phase of an emulsion. The hydrolysis and acidrelease do not occur until water contacts the solid acid-precursor.Methods used to delay acid generation may be used in conjunction withinclusion of solid acid-reactive material to accelerate acid generationbecause it may be desirable to delay acid generation but then to haveacid generated rapidly at a later point. The rate of acid generationfrom a particular solid acid-precursor in the presence of a scaleinhibitor or a particular mixture of a solid acid-precursor, a scaleinhibitor and a solid acid-reactive material having a particularchemical and physical make-up, including a coating if present, at aparticular temperature and in contact with a fluid or fluids of aparticular composition (for example pH and the concentration and natureof other components, especially electrolytes), is readily determined bysimple fluid analysis involving exposing the acid-precursor to the fluidor fluids under treatment conditions and monitoring the release of acid.

The rate of dissolution of the solid scale inhibitor, and of the solidacid-responsive material, are governed by similar factors (such as bythe choice of material, the ratio of materials, the particle size,calcining and coating of the solid material) and may readily bedetermined by similar fluid analysis. In certain embodiments, the solidacid-precursor particles, or the mixture particles, comprise materialsthat self-destruct (e.g. by complete hydrolysis and/or dissolution) insitu, that is, in the location where they are placed.

The particle sizes of the individual components of the mixture may bethe same or different. Almost any particle size may be used. Examples ofrelevant factors include the capability of equipment, the width of thefracture generated, and the desired rate and time of particledegradation. The rate of particle degradation is readily determined bysimple fluid analysis. In certain embodiments, sizes similar toproppants and fluid loss additives are utilized. Non-limiting examplesof suitable particle sizes include particles of similar size to variousproppant sizes such as particles meeting a 100 mesh, a 20/40 mesh,and/or a 30/60 mesh size standard. In certain embodiments, particlessizes may be selected that are larger than 20 microns, and/or that arelarger than 100 microns. In certain embodiments, solid acid-precursorsof the current invention may be used for delayed acid generation in acidfracturing in the ways in which the encapsulated acids described in U.S.Pat. No. 6,207,620, hereby incorporated in its entirety, are used.

Thus one embodiment of the invention is a method of acid fracturing witha solid acid-precursor and a scale inhibitor both present in thefracturing fluid. In certain embodiments, the solid acid-precursor isincluded in an otherwise conventional acid fracturing treatment (inwhich the fluid contains an acid such as HCl, HF, an organic acid ormixtures thereof). The initially present acids will tend to spend in thenear-wellbore or high permeability region of the formation, but thesolid acid-precursor will be carried farther into the fracture andgenerate acid in situ that will etch the fracture faces farther from thewellbore. In certain embodiments, the solid acid-precursor is includedas the only source of acid in the treatment. In certain embodiments, thetreatment fluid 106 includes proppant that holds the fracture open untilthe solid acid-precursor has hydrolyzed and dissolved.

In certain embodiments, the treatment fluid 106 includes the solidacid-precursor and the solid scale inhibitor, wherein both solids act asa proppant until the solids hydrolyze. In certain embodiments, thetreatment is an acid fracturing treatment with proppant or withoutproppant. In certain embodiments, a treatment is conducted as acost-minimization water-frac in which a low concentration, for exampleabout 0.05 kg/L, of solid acid-precursor or mixture is pumped at a highrate, for example up to about 3500 L/min or more, with little or noviscosifier in the carrier fluid 105. In certain embodiments, atreatment is conducted as a more conventional fracturing treatment, withviscosifiers in the carrier fluid 105, and higher concentrations, forexample up to about 0.6 kg/L, of solid acid-precursor or mixture. Thepumping rates, viscosifier amounts, and solid acid-precursor (ormixture) concentrations may vary in certain embodiments and examples areintended as non-limiting illustrations only.

In certain embodiments, viscosifiers include polymers or viscoelasticsurfactants typically used in fracturing, frac-packing and gravelpacking. When a high concentration of particles of solid acid-precursoror mixture is used, this may necessitate using a more viscous fluid thanis usually used in conventional acid fracturing. In certain embodiments,the solid acid-precursor and/or mixture has a lower density thanconventional proppants, allowing a lower viscosifier loading. In certainembodiments, the solid acid-precursor or mixture acts as a breaker forthe viscosifier, enhancing cleanup of the fracture 110. In certainembodiments, at least a portion of the solid acid-precursor or mixtureincludes fibers. The use of fibers may reduce or eliminate the need forincluding viscosifiers in the carrier fluid 105.

The amount of solid acid-precursor or mixture used in the treatmentfluid 106 depends upon factors including the temperature and the amountof acid needed. In certain embodiments, the solid acid-precursor isincluded in an amount between about 0.05 and about 0.6 kg/L. In certainpreferred embodiments, the solid acid-precursor is included in an amountbetween about 0.1 and 0.3 kg/L. In certain embodiments, the solidacid-precursor is included at between about 0.1 and about 0.3 kg/L). Incertain embodiments, the amount of scale inhibitor to be used is atleast about 0.01 kg/L. In certain embodiments, the treatment fluid 106further includes a diverter that diverts the fluid containing a solidacid-reactive material from already-present high permeability streaks,vugs, or natural fractures in the formation 104. In certain embodiments,acid generated from solid acid-precursors performs one or moreadditional functions of: etching fracture faces to increase fractureconductivity, breaking or aiding breaking a polymer or viscoelasticsurfactant, dissolving fluid loss additives, and/or dissolving scales orfines.

FIG. 2A is a schematic illustration 200 of a solid acid-responsivematerial 204 combined in a particle 202 with a solid acid-precursor 206.In the illustration 200, the solid acid-responsive material 204comprises a small portion of the particle 202, and as the solidacid-responsive material 204 dissolves and/or reacts, the surface of theparticle 202 is disrupted. As the solid acid-responsive material 204dissolves and/or reacts, the hydrolysis of the solid acid-precursor 206is enhanced and the solid acid-precursor 206 generates acid in thetreatment fluid 106. The mechanism of the solid acid-responsive material204 enhancing hydrolysis of the solid acid-precursor 206 is shown forillustration only, and in certain embodiments, other mechanisms may beutilized.

FIG. 3 is a schematic illustration of a treatment fluid 106. Thetreatment fluid 106 includes a carrier fluid 105, and a particle 202having a solid acid-responsive material 204 combined with a solidacid-precursor 206. The treatment fluid 106 is in contact with the solidacid-responsive material 204, in the illustration of FIG. 3 the contactoccurs due to the solid acid-responsive material 204 being included on aparticle with the solid acid-precursor 206. In certain embodiments (notshown), contact with the solid acid-responsive material 204 occurswithin the wellbore 102 and/or the formation 104. In certainembodiments, the solid acid-responsive material 204 is not present inthe system 100. The treatment fluid 106 further includes a solid scaleinhibitor 304, and is in contact with a divalent activator 302. FIG. 3is an illustration of one embodiment of a treatment fluid 106, whileother embodiments may have components not shown in FIG. 3 or may omitcomponents illustrated in FIG. 3.

The schematic flow diagram and related description which followsprovides an illustrative embodiment of performing operations for acidfracturing with scale inhibitor control. Operations illustrated areunderstood to be exemplary only, and operations may be combined ordivided, and added or removed, as well as re-ordered in whole or part,unless stated explicitly to the contrary herein.

FIG. 4 is schematic flow diagram of a technique 400 for acid fracturingand inhibiting scale. The technique 400 includes an operation 402 toprovide a treatment fluid including a carrier fluid, a solidacid-precursor, and a solid scale inhibitor. In certain embodiments, thetechnique 400 further includes an operation 404 to contact the treatmentfluid with a solid acid-responsive material. In certain embodiments, thetechnique 400 further includes an operation 406 to contact the treatmentfluid with a scale inhibitor activator, and an operation 408 to injectthe treatment fluid into a subterranean formation. In certainembodiments, the technique 400 further includes an operation 410 tohydrolyze a solid acid-precursor in the treatment fluid to form an acidin the subterranean formation. In certain embodiments, the techniquefurther includes an operation 412 to contact the solid acid-responsivematerial with acid within the formation.

As is evident from the figures and text presented above, a variety ofembodiments according to the present invention are contemplated.

In one exemplary embodiment, a method includes providing a treatmentfluid including a carrier fluid, a solid acid-precursor, and a solidscale inhibitor. In certain embodiments, the method further includesinjecting the treatment fluid into a subterranean formation, andhydrolyzing at least a portion of the solid acid-precursor to form anacid within the subterranean formation. In certain embodiments, themethod further includes contacting the treatment fluid with a solidacid-responsive material to the carrier fluid, and/or contacting thesolid acid-responsive material with acid within the subterraneanformation.

In certain embodiments, the solid acid-responsive material is combinedin a particle with the solid acid-precursor. In certain embodiments, thesolid acid-responsive material includes magnesium hydroxide, magnesiumcarbonate, dolomite, calcium carbonate, aluminum hydroxide, calciumoxalate, calcium phosphate, aluminum metaphosphate, sodium zincpotassium pholyphosphate glass, and/or sodium calcium magnesiumpolyphosphate glass. In certain embodiments, the solid acid-precursorincludes cyclic ester dimers of lactic acid, cyclic ester dimers ofglycolic acid, homopolymers of lactic acid, homopolymers of glycolicacid, copolymers of lactic acid, copolymers of glycolic acid, and/or acopolymer of at least one of glycolic acid and lactic acid combined withat least one moiety selected from the moieties consisting of ahydroxyl-containing moiety, carboxylic acid-containing moiety, andhydroxycarboxylic acid-containing moiety.

In certain embodiments, the method further includes contacting thetreatment fluid with a scale inhibitor activator present in an amountbetween about 0.1% and 50% by weight of the scale inhibitor. In certainembodiments, the method further includes the scale inhibitor activatorbeing a divalent ion, an ionic salt, and/or calcium chloride.

In one exemplary embodiment, a treatment fluid includes a carrier fluid,a solid acid-precursor, and a solid scale inhibitor. In certain furtherembodiments, the treatment fluid includes a solid acid-responsivematerial in contact with the treatment fluid. In certain embodiments,the solid acid-responsive material is physically mixed with the solidacid-precursor. In certain embodiments, the solid acid-responsivematerial is combined in a particle with the solid acid-precursor. Incertain embodiments, the solid acid-responsive material is a materialthat responds to an acid presence by dissolving and/or reacting.

In certain embodiments, the solid acid-responsive material includes anacid-precursor hydrolysis accelerant. In certain further embodiments,the accelerant is material of a subterranean formation. In certainembodiments, the accelerant includes magnesium hydroxide, magnesiumcarbonate, dolomite, calcium carbonate, aluminum hydroxide, calciumoxalate, calcium phosphate, aluminum metaphosphate, sodium zincpotassium pholyphosphate glass, and/or sodium calcium magnesiumpolyphosphate glass.

In certain embodiments, the treatment fluid includes a water-solubleacid-precursor hydrolysis accelerant. In certain further embodiments,the water-soluble acid-precursor hydrolysis accelerant includes anester, a cyclic ester, a diester, an anhydride, a lactone, an amide, ananhydride, an alkali metal alkoxide, a carbonate, a bicarbonate, analcohol, an alkali metal hydroxide, an ammonium hydroxide, an amine,and/or an alkanol amine. In certain embodiments, the water-solubleacid-precursor hydrolysis accelerant includes sodium hydroxide,potassium hydroxide, ammonium hydroxide, and/or propylene glycoldiacetate.

In certain embodiments, the solid acid-precursor includes cyclic esterdimers of lactic acid, cyclic ester dimers of glycolic acid,homopolymers of lactic acid, homopolymers of glycolic acid, copolymersof lactic acid, and/or copolymers of glycolic acid. In certainembodiments, the solid acid-precursor includes a copolymer of glycolicacid and/or lactic acid, combined with a moiety including ahydroxyl-containing moiety, a carboxylic acid-containing moiety, and/ora hydroxycarboxylic acid-containing moiety. In certain embodiments, thesolid acid-precursor further comprises a hydrolysis delaying coating.

In certain embodiments, the treatment fluid includes a scale inhibitoractivator present in an amount between about 0.1% and 50% by weight ofthe scale inhibitor. In certain further embodiments, the scale inhibitoractivator includes a divalent ion and/or an ionic salt. In certainembodiments, the activator includes calcium chloride. In certainembodiments, the treatment fluid includes hydrochloric acid,hydrofluoric acid, ammonium bifluoride, formic acid, acetic acid, lacticacid, glycolic acid, aminopolycarboxylic acids, polyaminopolycarboxylicacids, and/or an acid salt. In certain embodiments, the scale inhibitorincludes phosphonic acid, a phosphonic acid derivative, phosphate ester,phosphonate, a phosphonate polymer, an acrylate including phosphorous, amethacrylate including phosphorous, polycarboxylate, a polycarboxylateincluding phosphorous, a sulfonate, polyacrylate, polymethacrylate,phosphino-polyacrylate, a phosphonic acid derivative of ethylenediamine, phosphonic acid[1,2-ethanediylbis[nitrilobis(methylene)]]tetrakis (EDTMPA), a calciumsalt of EDTMPA, and/or a sodium salt of EDTMPA.

One exemplary embodiment is a system including a wellbore intersecting asubterranean formation, and an amount of treatment fluid including acarrier fluid, a solid acid-precursor, and a solid scale inhibitor. Thesystem further includes a pump structured to fracture the subterraneanformation, and to place the treatment fluid in the fracture. In certainembodiments, the system further includes a solid acid-responsivematerial in contact with the treatment fluid. In certain embodiments,the system further includes a scale inhibitor activator present in anamount between about 0.1% and 50% by weight of the scale inhibitor. Incertain embodiments, the solid acid-precursor further includes ahydrolysis delaying coating. In certain embodiments, the solidacid-precursor includes cyclic ester dimers of lactic acid, cyclic esterdimers of glycolic acid, homopolymers of lactic acid, homopolymers ofglycolic acid, copolymers of lactic acid, and/or copolymers of glycolicacid. In certain embodiments, the solid acid-precursor includes acopolymer of glycolic acid and/or lactic acid, combined with ahydroxyl-containing moiety, carboxylic acid-containing moiety, and/or ahydroxycarboxylic acid-containing moiety.

While the invention has been illustrated and described in detail in thedrawings and foregoing description, the same is to be considered asillustrative and not restrictive in character, it being understood thatonly the preferred embodiments have been shown and described and thatall changes and modifications that come within the spirit of theinventions are desired to be protected. It should be understood thatwhile the use of words such as preferable, preferably, preferred, morepreferred or exemplary utilized in the description above indicate thatthe feature so described may be more desirable or characteristic,nonetheless may not be necessary and embodiments lacking the same may becontemplated as within the scope of the invention, the scope beingdefined by the claims that follow. In reading the claims, it is intendedthat when words such as “a,” “an,” “at least one,” or “at least oneportion” are used there is no intention to limit the claim to only oneitem unless specifically stated to the contrary in the claim. When thelanguage “at least a portion” and/or “a portion” is used the item caninclude a portion and/or the entire item unless specifically stated tothe contrary.

1. A treatment fluid, comprising: a carrier fluid; a solidacid-precursor; and a solid scale inhibitor.
 2. The treatment fluid ofclaim 1, further comprising a solid acid-responsive material in contactwith the treatment fluid.
 3. The treatment fluid of claim 2, wherein thesolid acid-responsive material is physically mixed with the solidacid-precursor.
 4. The treatment fluid of claim 3, wherein the solidacid-responsive material is combined in a particle with the solidacid-precursor.
 5. The treatment fluid of claim 2, wherein the solidacid-responsive material comprises an acid-precursor hydrolysisaccelerant.
 6. The treatment fluid of claim 5, wherein the accelerantcomprises material of a subterranean formation.
 7. The treatment fluidof claim 5, wherein the accelerant comprises at least one materialselected from the materials consisting of magnesium hydroxide, magnesiumcarbonate, dolomite, calcium carbonate, aluminum hydroxide, calciumoxalate, calcium phosphate, aluminum metaphosphate, sodium zincpotassium polyphosphate glass, and sodium calcium magnesiumpolyphosphate glass.
 8. The treatment fluid of claim 2, wherein thesolid acid-responsive material is structured to respond to an acidpresence by at least one action selected from the group consisting ofdissolving and reacting.
 9. The treatment fluid of claim 1, furthercomprising a water-soluble acid-precursor hydrolysis accelerant.
 10. Thetreatment fluid of claim 9, wherein the water-soluble acid-precursorhydrolysis accelerant comprises at least one accelerant selected fromthe group consisting of an ester, a cyclic ester, a diester, ananhydride, a lactone, an amide, an alkali metal alkoxide, a carbonate, abicarbonate, an alcohol, an alkali metal hydroxide, an ammoniumhydroxide, an amine, and an alkanol amine.
 11. The treatment fluid ofclaim 9, wherein the water-soluble acid-precursor hydrolysis accelerantcomprises at least one accelerant selected from the group consisting ofsodium hydroxide, potassium hydroxide, ammonium hydroxide, and propyleneglycol diacetate.
 12. The treatment fluid of claim 1, further comprisinga scale inhibitor activator present in an amount between about 0.1% and50% by weight of the scale inhibitor.
 13. The treatment fluid of claim12 wherein the scale inhibitor activator comprises one componentselected from the group consisting of a divalent ion and an ionic salt.14. The treatment fluid of claim 12, wherein the scale inhibitoractivator comprises calcium chloride.
 15. The treatment fluid of claim1, wherein the solid acid-precursor comprises at least one precursorselected from the group consisting of cyclic ester dimers of lacticacid, cyclic ester dimers of glycolic acid, homopolymers of lactic acid,homopolymers of glycolic acid, copolymers of lactic acid, and copolymersof glycolic acid.
 16. The treatment fluid of claim 1, wherein the solidacid-precursor includes a copolymer of at least one of glycolic acid andlactic acid combined with at least one moiety selected from the moietiesconsisting of a hydroxyl-containing moiety, carboxylic acid-containingmoiety, and hydroxycarboxylic acid-containing moiety.
 17. The treatmentfluid of claim 1, wherein the carrier fluid comprises at least one acidselected from the group consisting of hydrochloric acid, hydrofluoricacid, ammonium bifluoride, formic acid, acetic acid, lactic acid,glycolic acid, aminopolycarboxylic acids, polyaminopolycarboxylic acids,and an acid salt.
 18. The treatment fluid of claim 1, wherein the scaleinhibitor includes an inhibitor selected from the group consisting ofphosphonic acid, a phosphonic acid derivative, phosphate ester,phosphonate, a phosphonate polymer, an acrylate including phosphorous, amethacrylate including phosphorous, polycarboxylate, a polycarboxylateincluding phosphorous, a sulfonate, polyacrylate, polymethacrylate,phosphino-polyacrylate, a phosphonic acid derivative of ethylenediamine, phosphonic acid[1,2-ethanediylbis[nitrilobis(methylene)]]tetrakis (EDTMPA), a calciumsalt of EDTMPA, and a sodium salt of EDTMPA.
 19. The treatment fluid ofclaim 1, wherein the solid acid-precursor further comprises a hydrolysisdelaying coating.
 20. The treatment fluid of claim 1, wherein the solidacid-precursor is present in an amount between about 0.05 and about 0.6kg/L.
 21. The treatment fluid of claim 1, wherein the solidacid-precursor is present in an amount between about 0.1 and about 0.3kg/L.
 22. The treatment fluid of claim 1, wherein the solid scaleinhibitor comprises a particle size greater than about 20 microns. 23.The treatment fluid of claim 1, wherein the solid scale inhibitorcomprises a particle size greater than about 100 microns.
 24. A system,comprising: a wellbore intersecting a subterranean formation; an amountof treatment fluid, comprising: a carrier fluid, a solid acid-precursor,and a solid scale inhibitor comprising a particle size greater thanabout 20 microns; and a pump structured to fracture the subterraneanformation, and to place the treatment fluid in the fracture.
 25. Thesystem of claim 24, further comprising a solid acid-responsive materialin contact with the treatment fluid.
 26. The system of claim 24, furthercomprising a scale inhibitor activator present in an amount betweenabout 0.1% and 50% by weight of the scale inhibitor.
 27. The system ofclaim 24, wherein the solid acid-precursor further comprises ahydrolysis delaying coating.
 28. The system of claim 24, wherein thesolid acid-precursor comprises at least one precursor selected from thegroup consisting of cyclic ester dimers of lactic acid, cyclic esterdimers of glycolic acid, homopolymers of lactic acid, homopolymers ofglycolic acid, copolymers of lactic acid, and copolymers of glycolicacid.
 29. The system of claim 24, wherein the solid acid-precursorincludes a copolymer of at least one of glycolic acid and lactic acidcombined with at least one moiety selected from the moieties consistingof a hydroxyl-containing moiety, carboxylic acid-containing moiety, andhydroxycarboxylic acid-containing moiety.